As the oil and gas industry are going to deeper water, inadvertent gas entry into the drilling riser is a challenge due to the fact that the high static pressure at the seabed causes the gas to be highly compressed and in dense phase. There are basically two ways of handling inadvertent gas entry into the drilling riser: divert or shut-in.
Before 2001, the recommended practice for the oil and gas industry was to divert as outlined in the 1st edition of API RP 64:
“In drilling operations utilizing subsea preventer equipment where gas may have passed the blowout preventers immediately before they are closed on a kick or where gas may surface after being trapped below the blowout preventer in normal kill operations, a diverter system should be considered to divert gas and wellbore fluids when the marine drilling riser unloads.”
In 2001, a new industry standard was described, giving a recommended practice to partly shut-in the drilling riser as stated in 2nd edition of API RP 64:
“In some designs, a mud/gas separator is utilized in the diverter system to separate the gas from the mud and return the mud to the system. Again, the design should not allow the diverter to completely shut-in the well.”
In recent years, a number of Managed Pressure Drilling (MPD) and Underbalanced drilling (UBD) solutions have been developed which also completely or partially shut-in the well and drilling riser, or by other means apply back-pressure to the well and drilling riser. However, these new solutions have been developed without any regulatory requirement to follow the basic safety analysis outlined in API RP 14C. API RP 14C was originally developed for Offshore Production Platforms, but also applies to Well Testing and Associated Well Control System.
The purpose of applying API RP 14C safety analysis and basic safety systems is to prevent undesirable events that could result in personnel injury, pollution or facility damage. One undesirable event can be overpressure. Overpressure is pressure in a process component in excess of the maximum allowable working pressure. Overpressure for a drilling riser can be caused by:                a) the static pressure of the drilling riser fluids in addition to the dynamic pressure loss in annulus exceeding the maximum allowable working pressure for the drilling riser,        b) inflow to the drilling riser exceeding outflow from the drilling riser,        c) the drilling riser being partly or fully shut-in and gas rapidly expanding in the drilling riser faster than the outflow from the drilling riser, or        d) a combination of a), b) and c) above.        
In some previous designs (as shown, for example, in FIG. 1), the drilling riser 3 has been partly shut-in by closing both the diverter line 10, the diverter element 11 and the mud return flowline 12, and the drilling riser fluids have been routed to a Mud Gas Separator (MGS) 13, as described in 2nd edition of API RP 64.
However, handling gas that has inadvertently entered into the drilling riser 3 by this method is unsafe because as the gas travels up the drilling riser 3, it will expand rapidly and push an accelerating liquid slug in front. Since there are no means for controlling the flow to the MGS 13, a typical result of such a design will be an undesirable event such as overfilling the MGS 13. Overfilling the MGS 13 will result in flooding the entire MGS vent line 23 to an outlet elevation typically four meter above the derrick. This will also increase the pressure in the drilling riser 3 and diverter housing below the diverter element 11, equivalent to the additional hydrostatic pressure caused by the elevation difference between the diverter line 10 outlets and the MGS vent line 23 outlet. In a worst case scenario, this can then also lead to a second undesirable event, such as overpressure of the drilling riser 3 or slip joint 2.
Normally the slip joint 2 will be the weakest point in a drilling riser and diverter system. The diverter system normally includes a diverter element 11 and two diverter lines 10 provided with isolation valves in each line. The slip joint 2 is typically designed with one packer 14 used under normal drilling operation pressurized to 100 psi (6.9 bar) and a second packer 15 pressurized to 500 psi (34.5 bar), which should be automatically pressurized when the diverter element 11 is closed and fluid diverted through the diverter lines 10.
FIG. 2 shows a simplified schematic representation of a drilling riser gas handling system according to prior art where an annular preventer 1 is installed in the drilling riser 3 below the slip joint 2 and the flow is routed to a MGS 13 through a Pressure Control Valve (PCV) 6 and a Pressure Relief Valve (PRV) 20 located under said annular preventer 1. This design is a significant improvement compared to the prior art described above, since the applied backpressure will reduce the peak flow to the MGS 13 and gas can be vented in a more controlled manner. This design can be compared with opening a champagne bottle gentlly by holding back the pressure with one hand on the champagne cork rather than opening the bottle with both of your thumbs pushing on the cork.
However, this system is more complex with more risk for mechanical and/or human errors and the possibility to overpressure the drilling riser 3 since restricting the flow to the MGS 13 will necessarily result in a pressure increase in the drilling riser 3. For this reason, the Pressure Relief Valve (PRV) 20 is normally installed upstream the first isolation valve 22 in the return line 5 to the mud system or directly on the drilling riser 3 below the annular preventer 1.
Introducing PRVs on a topside installation with potential release of a large amount hydrocarbon gas requires a lot of safety considerations, and it is a challenge to follow the guidelines and standards outlined in the following API documentations;
API RP 14C—Recommended Practice for Analysis, Design, Installation, and Testing of Basic Surface Safety Systems for Offshore Production Platforms
API Standard 520—Part I—Sizing and Selection Sizing, Selection, and Installation of Pressure-relieving Devices in Refineries.
API RP 520—Part II—Installation Sizing, Selection, and Installation of Pressure-relieving Devices in Refineries.
API Standard 521—Pressure-relieving and Depressuring Systems.
Although these API standards and recommendations are not made for normal drilling operations, many of the guidelines in these specifications also have relevance, especially when introducing PCV or other means of applying back pressure to the low pressure drilling riser. Some of the guidelines in these specs are discussed further in detailed description.